Convertiball

ABSTRACT

Provided is a plug apparatus, the apparatus including a cone shaped wedge having a first end and a second end and having an inside surface and an outside surface, the cone shaped wedge having, at least in some part, a decreasing diameter on the outside surface and a constant diameter on the inside surface from the first end to the second end, a slip, comprising a tapered inner surface, configured to encircle the second end of the cone shaped wedge, a sealing ring, having an annular body, encircled around the cone shaped wedge and near the first end of the cone shaped wedge, and a mandrel positioned inside the cone shaped wedge, the mandrel having an open cylindrical shape and having a first end and a second end.

BACKGROUND 1. Field

The present disclosure relates generally to plugs that may be used toisolate a portion of a well, and more particularly, to plugs that may beused in fracturing or other processes for stimulating oil and gas wells.

2. Description of the Related Art

Hydrocarbons, such as oil and gas, may be recovered from various typesof subsurface geological formations. The formations typically consist ofa porous layer, such as limestone and sands, overlaid by a nonporouslayer. Hydrocarbons cannot rise through the nonporous layer. Thus, theporous layer forms a reservoir, that is, a volume in which hydrocarbonsaccumulate. A well is drilled through the earth until the hydrocarbonbearing formation is reached. Hydrocarbons then are able to flow fromthe porous formation into the well.

In the most basic form of rotary drilling methods, a drill bit isattached to a series of pipe sections or “joints” referred to as a drillstring. The drill string is suspended from a derrick and rotated by amotor in the derrick. A drilling fluid or “mud” is pumped down the drillstring, through the bit, and into the bore of the well. This fluidserves to lubricate the bit. The drilling mud also carries cuttings fromthe drilling process back to the surface as it travels up the wellbore.As the drilling progresses downward, the drill string is extended byadding more joints of pipe.

A modern oil well typically includes a number of tubes extending whollyor partially within other tubes. That is, a well is first drilled to acertain depth. Large diameter pipes, or casings, are placed in the welland cemented in place to prevent the sides of the borehole from cavingin. The casing is cemented in the well by injecting a cement slurry downthe casing, out the bottom of the casing, and up into the well annulus,that it, the gap between the casing and the bore of the well. The cementthen is allowed to harden into a continuous seal throughout the annulus.

After the initial section has been drilled, cased, and cemented,drilling will proceed with a somewhat smaller wellbore. The smaller boreis lined with large, but somewhat smaller pipes or “liners.” The lineris suspended from the original or “host” casing by an anchor or“hanger.” A well may include a series of smaller liners, and may extendfor many thousands of feet, commonly up to and over 25,000 feet.

Hydrocarbons, however, are not always able to flow easily from aformation to a well. Some subsurface formations, such as sandstone, arevery porous. Hydrocarbons can flow easily from the formation into awell. Other formations, however, such as shale rock, limestone, and coalbeds, are only minimally porous. The formation may contain largequantities of hydrocarbons, but production through a conventional wellmay not be commercially practical because hydrocarbons flow though theformation and collect in the well at very low rates. The industry,therefore, relies on various techniques for improving the well andstimulating production from formations and especially from formationsthat are relatively nonporous.

Perhaps the most important stimulation technique is the combination ofhorizontal wellbores and hydraulic fracturing. A well will be drilledvertically until it approaches a formation. It then will be diverted,and drilled in a more or less horizontal direction, so that the boreholeextends along the formation instead of passing through it. More of theformation is exposed to the borehole, and the average distancehydrocarbons must flow to reach the well is decreased. Fractures thenare created in the formation which will allow hydrocarbons to flow moreeasily from the formation.

Fracturing a formation is accomplished by pumping fluid, most commonlywater, into the well at high pressure and flow rates. Proppants, such asgrains of sand, ceramic or other particulates, usually are added to thefluid along with gelling agents to create a slurry. The slurry is forcedinto the formation at rates faster than can be accepted by the existingpores, fractures, faults, vugs, caverns, or other spaces within theformation. Pressure builds rapidly to the point where the formationfails and begins to fracture. Continued pumping of fluid into theformation will tend to cause the initial fractures to widen and extendfurther away from the wellbore, creating flow paths to the well. Theproppant serves to prevent fractures from closing when pumping isstopped.

A formation rarely will be fractured all at once. It typically will befractured in many different locations or zones and in many differentstages. Fluids will be pumped into the well to fracture the formation ina first zone. After the initial zone is fractured, pumping is stopped,and a plug is installed in the liner at a point above the fracturedzone. Pumping is resumed, and fluids are pumped into the well tofracture the formation in a second zone located above the plug. Thatprocess is repeated for zones further up the formation until theformation has been completely fractured.

Fracturing typically involves installing a production liner in theportion of the wellbore passing through the hydrocarbon bearingformation. The production liner may incorporate valves, typicallysliding sleeve “ball-drop” valves. The valve may be actuated bydeploying a ball into the valve to open ports in the valve and to plugthe valve below the ports. The ball restricts flow through the liner anddiverts fluid through the ports and into the formation. Once fracturingis complete various operations will be performed to remove the balls andallow fluids from the formation to enter the liner and travel to thesurface.

In many wells, however, the production liner does not incorporatevalves. Instead, fracturing will be accomplished by “plugging andperfing” the liner. In a “plug and perf” job, the production liner ismade up from standard joints of liner. The liner does not have anyopenings through its sidewalls, nor does it incorporate frac valves. Itis installed in the wellbore and perforated, that is, holes are punchedin the liner walls. The perforations typically are created by so-called“perf” guns which discharge shaped charges through the liner and, ifpresent, adjacent cement.

A plug and perf operation can allow a well to be fractured at manydifferent locations in many distinct stages. The liner typically will beperforated first in a zone near the bottom of the well. Fluids then arepumped into the well to fracture the formation in the vicinity of thebottom perforations. Alternately, an initiator or “toe” valve may beincorporated into the liner and used to fracture the initial, bottomzone.

After the bottom zone is fractured, a tool string is deployed into theliner. The tool string typically includes a plug, a setting tool, andperf guns. The plug is positioned at a location above the fractured zoneand then installed by actuating the setting tool. Once the plug is set,the perf guns are fired to perforate the liner again, this time in asecond zone located above the plug. The tool string, less the plug, thenis withdrawn from the liner. Very commonly, the plug will be a “balldrop” plug which is shut by deploying or “dropping” a ball onto theplug. The ball will restrict fluids from flowing through and past theplug. When fluids are injected into the liner, therefore, they will beforced to flow out the perforations and into the second zone. After thesecond zone is fractured, the process is repeated with additional plugsuntil all zones in the well are fractured.

After the well has been fractured, however, plugs may interfere withinstallation of production equipment in the liner. They also mayrestrict the flow of production fluids upward through the liner. Thus,the plugs typically are removed from the liner after the well has beenfractured, most commonly by drilling out the plugs. Most plugs will befabricated from softer, more easily drillable materials such ascomposites and cast iron to speed up that process.

Many conventional ball drop plugs, especially those incorporatingcomposite materials, have a common basic design built around a centralsupport mandrel. The support mandrel is generally cylindrical andsomewhat elongated. It has a central conduit extending axially throughit. The support mandrel serves as a core for the plug and providessupport for the other plug components. The other plug components—slips,wedges, and sealing elements—are all generally annular and are carriedon and around the support mandrel in an array extending along the lengthof the mandrel. The plug is set by squeezing the components together toexpand the slips and sealing elements radially outward into contact withthe liner.

The support mandrel has a ball seat at or very near the upper end of themandrel central conduit. Once the plug is installed, and the settingtool withdrawn, fluids can flow in both directions through the centralconduit. When a ball is deployed onto the ball seat, however, the ballwill restrict fluid from flowing downward through the plug. Such designsare well known in the art and variations thereof are disclosed, forexample, in U.S. Pat. No. 7,475,736 to D. Lehr et al., U.S. Pat. No.7,789,137 to R. Turley et al., U.S. Pat. No. 8,047,280 to L. Tran etal., and U.S. Pat. No. 9,316,086 to D. VanLue. Plugs of that generaldesign also are commercially available from many differentmanufacturers, such as the Diamondback composite drillable frac plugavailable from Schlumberger, Houston, Tex., and the TruFrac compositefrac plug available from Weatherford, Houston, Tex.

Ball drop plugs, however, do not allow an operator to easily pressuretest a plug to ensure that it has been installed properly—the linertypically will have been perforated by the time a ball is deployed.Moreover, a significant amount of fluid must be pumped into a well todeploy balls into the valves, and especially into valves installed inhorizontal portions of a well. A ball cannot drop into a plug under theinfluence of gravity alone. Water may be hard to come by and costly.Disposal or recycling of frac fluids also may be difficult or expensive.Thus, some operators prefer to pump a ball into the well with the plug.The plug may be pressure tested before the perf guns are fired, and theball may be seated in the plug with little or no extra fluid.

“Caged ball” frac plugs represent one approach to accomplish that. Cagedball plugs incorporate a cage or some other sort of restrictor above theball seat in the plug. A ball is installed in the cage before the plugis run into a well. Thus, the plug may be pressure tested before theperf guns are fired. The ball also may be seated by pumping only a minoramount of fluid. The ball typically is free to flow on or off the seat,but the cage limits travel of the ball to the immediate vicinity of theseat. Many such plugs are commercially sold, including the Boss Hog ballcheck plugs sold by Downhole Technology LLC, Houston, Tex., and OriginalSeries caged ball plugs sold by JK Enterprises, Bridgeport, Tex.

While caged ball plugs represent a viable option if operations proceedaccording to plan, they can create significant issues, especially wheninstalled in horizontal portions of a well. That is, if a perf gun failsto fire for whatever reason, another perf gun cannot be pumped into theliner. The plug will prevent fluid from flowing into the liner. Thesecond perf gun will have to deployed into horizontal sections of thewell via a tractor tool, which adds the cost of the tractor run andattendant delay to the operation.

“Ball on seat” frac plugs provide another option. Many are soldcommercially, including the Boss Hog ball in place plugs sold byDownhole Technology. When a ball-on-seat frac plug is readied fordeployment into a well, a ball is installed between the plug and thesetting tool. Once the plug is set and the setting tool detached, theball may be seated by pumping a small amount of fluid. The plug may bepressure tested if desired before firing the perf guns. Travel of theball, however, is not restricted. Thus, if the perf guns fail to fire,the tool string can be pulled out of the well, and the ball will flow upand out of the liner with production fluids. Another perf gun then canbe pumped into the liner. While a tractor run will not be necessary,ball-on-seat plugs still add significant delay costs if perf guns failto fire.

The statements in this section are intended to provide backgroundinformation related to the invention disclosed and claimed herein. Suchinformation may or may not constitute prior art. It will be appreciatedfrom the foregoing, however, that there remains a need for new andimproved plugs for use in fracturing oil and gas wells or in otheroperations that require a portion of the well to be isolated. Suchdisadvantages and others inherent in the prior art are addressed byvarious aspects and embodiments of the subject invention.

SUMMARY

The following is a non-exhaustive listing of some aspects of the presenttechniques. These and other aspects are described in the followingdisclosure.

Some aspects include a plug apparatus, the apparatus including a coneshaped wedge having a first end and a second end and having an insidesurface and an outside surface, the cone shaped wedge having, at leastin some part, a decreasing diameter on the outside surface and aconstant diameter on the inside surface from the first end to the secondend, a slip, comprising a tapered inner surface, configured to encirclethe second end of the cone shaped wedge, a sealing ring, having anannular body, encircled around the cone shaped wedge and near the firstend of the cone shaped wedge, and a mandrel positioned inside the coneshaped wedge, the mandrel having an open cylindrical shape and having afirst end and a second end.

BRIEF DESCRIPTION OF THE DRAWINGS

The above-mentioned aspects and other aspects of the present techniqueswill be better understood when the present application is read in viewof the following figures in which like numbers indicate similar oridentical elements:

FIGS. 1A, 2A, 3A, and 4A (“FIGS. 1”) are sequential schematicrepresentations showing a well 1 being readied for production or“completed.”

FIG. 1A is a schematic illustration of a liner assembly being cementedin a bore of a well.

FIG. 1B is a schematic illustration of the initial stage of a “plug andperf” fracturing operation showing liner assembly installed and cementedin wellbore.

FIG. 1C is a schematic illustration of an early stage of the plug andperf fracturing operation which shows a tool string deployed into linerassembly.

FIG. 1D is a schematic illustration of liner assembly after completionof the plug and perf fracturing operation, and before removal of plugsfrom liner.

FIGS. 2A, 2B, 2C, and 2D (“FIGS. 2”) are sequential axialcross-sectional views of a first frac plug in a liner, in accordancewith some of the embodiments.

FIG. 2A shows the first frac plug in an unset, open state as it is runinto a well to a desired location in a liner, in accordance with some ofthe embodiments.

FIG. 2B shows the first frac plug after it has been set in a liner and asetting tool has been released from the frac plug, and with the fracplug still in its open state, in accordance with some of theembodiments.

FIG. 2C shows the first set frac plug in the process of being shut witha stopple, in accordance with some of the embodiments.

FIG. 2D shows the first frac plug after it has been shut with a stoppleto restrict the flow of fluids downward through the frac plug, inaccordance with some of the embodiments.

FIG. 3 is an axial cross-sectional view of an annular wedge of the firstfrac plug, in accordance with some of the embodiments.

FIG. 4 is a radial cross-section view of an annular slip, in accordancewith some of the embodiments.

FIG. 5 is a top elevational view of a setting ring, in accordance withsome of the embodiments.

FIG. 6 is an axial cross-sectional view of setting ring, in accordancewith some of the embodiments.

FIG. 7 is an axial cross-sectional view of a gauge ring, in accordancewith some of the embodiments.

FIG. 8 is a bottom elevational view of a gauge ring, in accordance withsome of the embodiments.

FIG. 9 is an axial cross-sectional view of a mandrel, in accordance withsome of the embodiments.

FIG. 10 is an isometric view of a stopple, in accordance with some ofthe embodiments.

FIG. 11 is a top cross-sectional view of a second exemplary frac plug,in accordance with some of the embodiments.

FIG. 12 is an isomeric cross-sectional view of the second exemplary fracplug, in accordance with some of the embodiments.

FIG. 13 is an isomeric whole view of the second exemplary frac plug, inaccordance with some of the embodiments.

FIG. 14 is a top exploded cross-sectional view of the second exemplaryfrac plug, in accordance with some of the embodiments.

FIG. 15 is an isomeric cross-sectional view of the second exemplary fracplug, where wireline setting tool is disengaged, in accordance with someof the embodiments.

FIG. 16 is an isomeric cross-sectional view of the second exemplary fracplug, during flow and prior to “Conversion”, in accordance with some ofthe embodiments.

FIG. 17 is an isomeric cross-sectional view of the second exemplary fracplug, during flow (the flow shown by the dotted line arrows) and priorto “Conversion”, in accordance with some of the embodiments.

FIG. 18 is an isomeric cross-sectional view of the second exemplary fracplug, where the frac plug is converted and sealed, in accordance withsome of the embodiments.

FIG. 19 is a zoomed isomeric whole view of ports of the second exemplaryfrac plug, in accordance with some of the embodiments.

FIG. 20 is a zoomed isomeric cross-sectional view of ports of the secondexemplary frac plug, in accordance with some of the embodiments.

FIG. 21 is an isomeric cross-sectional view of the second exemplary fracplug, with isomeric whole view of the mandrel for port visibility, inaccordance with some of the embodiments.

While the present techniques are susceptible to various modificationsand alternative forms, specific embodiments thereof are shown by way ofexample in the drawings and will herein be described in detail. Thedrawings may not be to scale. It should be understood, however, that thedrawings and detailed description thereto are not intended to limit thepresent techniques to the particular form disclosed, but to thecontrary, the intention is to cover all modifications, equivalents, andalternatives falling within the spirit and scope of the presenttechniques as defined by the appended claims.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

To mitigate the problems described herein, the inventors had to bothinvent solutions and, in some cases just as importantly, recognizeproblems overlooked (or not yet foreseen) by others in the field of oilextraction. Indeed, the inventors wish to emphasize the difficulty ofrecognizing those problems that are nascent and will become much moreapparent in the future should trends in industry continue as theinventors expect. Further, because multiple problems are addressed, itshould be understood that some embodiments are problem-specific, and notall embodiments address every problem with traditional systems describedherein or provide every benefit described herein. That said,improvements that solve various permutations of these problems aredescribed below.

In some embodiments, a frac plug 30 may be described by reference toFIGS. 1-10. As may be seen in the schematic representations of FIG. 1,frac plug 30 may be used to perform a “plug and perf” fracturingoperation in an oil and gas well 1. Referring first to FIG. 1A, well 1is serviced by a derrick 2 and various surface and downhole equipmentfor pumping cement and circulating fluids (not shown). The upper portionof well 1 is provided with a casing 3, while the lower portion is anopen bore 4 extending generally horizontally through a hydrocarbonbearing formation 5.

In some embodiments, a liner assembly 10 is suspended from casing 3 by aliner hanger 11 and extends through open bore 4. Liner assembly 10 mayinclude various tools, including toe valve 12 and a float assembly 13.Float assembly 13 may include various tools that assist in running liner10 into well 1 and cementing it in bore 4, such as a landing collar 14,a float collar 15, and a float shoe 16.

FIG. 1A depicts well 1 as liner 10 is being cemented in bore 4. Aquantity or “plug” of cement 6 is being pumped into liner 10, out itslower end, and into the annulus between liner 10 and bore 4. As cement 6is pumped, it displaces drilling fluids 7 already present in liner 10and the annulus. A wiper plug 17 is being pumped behind cement 6. Itfollows the plug of cement 6 as it flows through liner 10. Wiper plug 17will help clean and remove cement 6 from the inside of liner 10. It willpass through toe valve 12 and eventually seat on landing collar 14 infloat assembly 13. Pumping will continue until cement 6 completely fillsthe annulus between liner 10 and bore 4. It then will be allowed to set,as seen in FIG. 1B.

FIG. 1B shows well 1 after the initial stage of a frac job has beencompleted. Derrick 2 and the cementing equipment have been replaced bywell head 8 and other surface equipment (not shown) which will injectfrac fluids into well 1 at high pressures and flow rates. Toe valve 12was run in on liner 10 in its shut position, i.e., with toe valve 12closed. Toe valve 12 now has been opened. Fluid has been introduced intoformation 5 via open toe valve 12, and fractures 9 extending from toevalve 12 have been created in a first zone near the bottom of well 1.

In some embodiments, a frac job may proceed in stages from the lowermostzone in a well to the uppermost zone. Thus, FIG. 1C shows that a “plugand perf” tool string 20 has been run into liner 10 on a wireline 23.Tool string 20 comprises a perf gun 21, a setting tool 22, and a fracplug 30 a. Tool string 20 is positioned in liner 10 such that frac plug30 a is uphole from toe valve 12. Frac plug 30 a is coupled to settingtool 22 and may be installed in liner 10 by actuating setting tool 22via wireline 23. Once plug 30 a is installed, setting tool 22 may bereleased from plug 30 a. Perf gun 21 then may be fired to createperforations 24 a in liner 10 uphole from plug 30 a. Perf gun 21 andsetting tool 22 then will be pulled out of well 1 by wireline 23.

As described in detail below, a frac stopple 31 (not shown in FIG. 1)then may be released into plug 30 a to restrict the downward flow offluids through plug 30 a. Plug 30 a, therefore, will substantiallyisolate the lower portion of well 1 and the first fractures 9 extendingfrom toe valve 12. Fluid then may be pumped into liner 10 and forced outthrough perforations 24 a to create fractures 9 (shown in FIG. 1D) in asecond zone. After fractures 9 have been sufficiently developed, pumpingmay be stopped and valves in well head 8 will be closed to shut in thewell 1. After a period of time, fluid will be allowed to flow out offractures 9, through liner 10 and casing 3, to the surface.

In some embodiments, additional plugs 30 b to 30 z then may be run intowell 1 and set and shut or in certain embodiments, deployed, liner 10will be perforated at perforations 24 b to 24 z, and well 1 will befractured in succession as described above until, as shown in FIG. 1D,all stages of the frac job have been completed and fractures 9 have beenestablished in all zones. Once the fracturing operation has beencompleted, plugs 30 may be drilled out and removed from liner 10.Production equipment then will be installed in the well and at thesurface to control production from well 1.

The terms “upper” and “lower” and “uphole” and “downhole” as used hereinto describe location or orientation are relative to the well and to thetool as run into and installed in the well. Thus, “upper” and “uphole”refers to a location or orientation toward the upper or surface end ofthe well. “Lower” or “downhole” is relative to the lower end or bottomof the well. It also will be appreciated that the course of the wellboremay not necessarily be as depicted schematically in FIG. 1. Depending onthe location and orientation of the hydrocarbon bearing formation to beaccessed, the course of the wellbore may be more or less deviated in anynumber of directions.

In some embodiments, “Axial,” “radial,” “angularly,” and forms thereofreference the central axis of the tools. For example, axial movement orposition refers to movement or position generally along or parallel tothe central axis. “Lateral” movement and the like also generally referto up and down movement or positions up and down the tool. “Radial” willrefer to positions or movement toward or away from the central axis.

As discussed above, frac plugs may run into a well in an unset, openposition, but then may be set and shut to force fluid from a liner intoa formation. Broad embodiments incorporate a stopple that may bereleased to shut the plug once it has been set in a liner. For example,consider a frac plug 30 which is shown in greater detail in FIG. 2, as afirst exemplary frac plug, in accordance with some of the embodiments.

As shown in FIG. 2, frac plug 30 may comprise an annular wedge 34, asealing ring 35, an annular slip 36, a setting ring 37, a gauge ring 38,a mandrel 39, and a stopple 31. Wedge 34, sealing ring 35, and slip 36may have truncated inverted conical or other tapered surfaces. Thosesurfaces complement each other and allow wedge 34 to be driven into andradially expand sealing ring 35 and slip 36 to seal and anchor plug 30in liner 10. In some embodiments, except in that it incorporates mandrel39 and stopple 31, plug 30 is similar to frac plug 30 disclosed in U.S.Pat. No. 9,835,003 to M. Harris et al. and the RzrFrac plug sold byRubicon Oilfield International, Houston, Tex.

An example of an annular wedge 34 is shown in isolation in FIG. 3. Asseen therein, wedge 34 may have an upper portion that may be describedin general terms as having an annular or open cylindrical shape. Thelower portion of wedge 34 may comprise a plurality of collet fingers 41.(Certain other embodiments may have structures other than colletfingers, including rods such as those shown in FIG. 15 item 41, thatperform similar functions). Collet fingers 41 are integrally formed withwedge 34 and extend axially downward from the lower end of the wedgeupper portion. Collet fingers 41 are spaced circumferentially aroundannular wedge 34 and terminate in collet heads 42. As will beappreciated from the discussion that follows, collet fingers 41 mayprovide support for slip 36 as it is assembled and a base for connectinggage ring 38.

In some embodiments, wedge 34 may also have an axial passage or bore 43extending through its upper portion. As seen in FIG. 3, an inner mandrelseat 44 may be defined in wedge bore 43, bore 43 otherwise having asubstantially uniform diameter, and in some embodiments there issubstantially uniform ID at least in part. In certain other embodiments,the inner diameter is tapered. In some other embodiments, the innerdiameter is alternately tapered and substantially uniform. Theappropriate inner diameter shape is determined by its function and thecorresponding tool portions with which it is to interact. By example,the inner diameter can be designed to interact with the mandrel to,among other things, seat the inner/outer wedge as the mandrel advancesdownward through the tool and modulate the fluid flow toward the portsin the mandrel, regulating the fluid flow and pressure above and belowthe tool. Mandrel seat 44 may be provided by a shallow angle, upwardfacing tapered reduction in the diameter of wedge bore 43 situatedaxially below the upper end of wedge 34.

In some embodiments, the upper portion of wedge 34 has an outer that maybe truncated inverted conical surface 45. That is, outer conical surface45 tapers downwardly and inwardly, and the diameter of its upper end isgreater than the diameter of its lower end. The upper end of wedge 34may have a substantially cylindrical outer surface if desired. That is,conical surface 45 does not necessarily extend all the way to the upperend of wedge 34. In some embodiments, however, it extends along thesubstantially majority of the upper portion of wedge 34.

In some embodiments, sealing ring 35 of plug 30 may have a relativelyshort, annular body 51 defining an axial passage or bore. The ring boremay have an inverted truncated conical shape, that is, it tapersradially inward from its upper end to its lower end. The inner taper ofthe bore of sealing ring 35 may be complementary to the taper providedon outer conical surface 45 of wedge 34. In some embodiments, sealingring 35 may be provided with one or more elastomeric seals whichultimately will enhance the seal between plug 30 and liner 10 when plug30 is set. Thus, ring body 51 is provided with one or more outerelastomeric seals 52 in corresponding grooves on the outer surface ofring body 51. One or more inner elastomeric seals 53 may be provided incorresponding grooves in the ring bore. Elastomeric seals 52 and 53 maybe molded in the grooves or they may be molded and then insertedtherein. Other seal configurations may be used, however, or the sealsmay be eliminated depending on the design of the sealing ring and thematerials from which it is fabricated.

Slip 36 of plug 30 may be designed to grip and engage liner 10. Though,in some embodiments referred to in the singular, slip 36 of plug 30 isan assembly of discrete, separate slip segments. As shown in FIG. 4,slip 36 may have six individual slip segments 36 a to 36 f. More orfewer segments may be used if desired, but in any event, individual slipsegments 36 a-f may be visualized as lateral segments of an opencylinder. When plug 30 is in its run-in condition, as shown in FIG. 2A,segments 36 a-f are aligned along, and arranged angularly about the toolaxis. In some embodiments, slip segments 36 a-f may be closely adjacentor abuts each other. Thus, slip segments 36 a-f collectively may definean open cylindrical slip 36 having an axial inner passage or bore 61.

In some embodiments, bore 61 of slip 36 may have a generally truncatedinverted conical surface. That is, slip bore 61 tapers radially inwardfrom top to bottom, and the diameter of slip bore 61 at its upper end isgreater than the diameter at its lower end. In some embodiments, thetaper in slip bore 61 is complementary to the taper on outer conicalsurface 45 of the upper portion of wedge 34.

In some embodiments, the outer surface of slip 36 may be cylindrical. Insome embodiments, it is provided with features to assist slip 36 inengaging and gripping liner 10 when plug 30 is set. Thus, for example,slip 36 may be provided with high-strength or hardened particles, gritor inserts, such as buttons 62 embedded in its outer surface. Buttons 62may be, for example, a ceramic material containing aluminum, such as afused alumina or sintered bauxite, or zirconia, such as CeramaZircavailable from Precision Ceramics. Buttons also may be fabricated fromheat treated steel or cast iron, fused or sintered high-strengthmaterials, or a carbide such as tungsten carbide. The precise number andarrangement of buttons 62 or other such members may be varied. The outersurface of slip 36 also may be provided with teeth or serrations inaddition to or in lieu of buttons or other gripping features.

In some embodiments, plug 30 may be set in liner 10 by actuating settingtool 22 via wireline 23. When actuated, setting tool 22 will driveannular wedge 34 into sealing ring 35 and annular slip 36. As wedge 34is driven downward, it will force sealing ring 35 and slip 36 to expandand seal and anchor 30 in liner 10. The setting of plug 30 may beunderstood in greater detail by comparing FIG. 2A and FIG. 2B. FIG. 2Ashows plug 30 in its run-in condition. FIG. 2B shows plug 30 after ithas been set in liner 10.

As shown in FIG. 2A, when plug 30 is assembled for running into a well,slip 36 may be disposed around collet fingers 41 of wedge 34 with theupper end of slip 36 extending over the lower portion of outer conicalsurface 45 of wedge 34. Outer conical surface 45 of wedge 34 thus isreceived in and engages conical bore 61 of slip 36.

In some embodiments, sealing ring 35 is carried on outer conical surface45 of wedge 34 near its lower end such that it abuts the upper end ofslip 36. Slip segments 36 a-f, in some embodiments, are secured at theirupper ends. Thus, for example, the lower end of sealing ring 35 isprovided with an annular projection or lip 54. Slip segments 36 a-f havea complementary lip 63 on their upper ends. Sealing ring lip 54 and sliplip 63 engage each other, thus securing the upper end of slip 36.

In some embodiments, collet fingers 41 extend downward through slip bore61 and terminate beyond the lower end of slip 36. Setting ring 37 iscarried slidably around that lower portion of collet fingers 41. Moreparticularly, the upper end of setting ring 37 abuts the lower end ofslip 36 and the lower end of setting ring 37 abuts heads 42 of colletfingers 41 and an upward facing shoulder on gauge ring 38.

An example of a setting ring 37 is shown in isolation in FIGS. 5-6. Asshown therein, setting ring 37 may have an annular body 71 having aplurality of keys 72. Keys 72 are arranged circumferentially on theinner surface or bore of setting ring body 71 and protrude radiallyinward. Setting ring 37 is slidably carried around the lower portion ofcollet fingers 41 such that keys 72 on setting ring 37 extend inwardinto slots 46 between collet fingers 41.

As shown in FIG. 2A, gauge ring 38 may be viewed as a bottom cap forplug 30. It is attached to the lower end of collet fingers 41 andextends generally around setting ring 37 and the lower end of slip 36.More particularly, and referring to FIG. 2A and to FIGS. 7-8 which showgauge ring 38 in isolation, it will be appreciated that the lowerportion of gauge ring 38 is generally enlarged and fits around and belowheads 42 of collet fingers 41. Gauge ring 38 may be connected to heads42 of collet fingers 41, for example, by fasteners. The fasteners may bescrews, bolts, or pins inserted through radial holes 81 in the lowerportion of gauge ring 38 (see FIG. 7) and into radial holes 47 providedin collet heads 42 (see FIG. 3).

In some embodiments, gauge ring 38 may have a relatively thin upperperimeter wall or skirt 82 extending upwardly from its lower portion.Skirt 82 extends upwardly beyond setting ring 37 and terminates justbeyond the lower end of slip 36. Gauge ring 38 and, in particular, skirt82 is thus able to hold the lower portions of slip segments 36 a-ftogether in a close annular arrangement.

In some embodiments, gauge ring 38 may help protect the lower end ofplug 30 as it is deployed into a well. Skirt 36 of gauge ring 38 extendsaround the lower portions of slip segments 36 a-f, thus helping toprotect them from catching on debris, protrusions, and the like thatmight cause them to deploy prematurely. It also will be noted that theouter diameter of gauge ring 38 may be greater than the outer diameterof setting ring 37, slips 36, sealing ring 35, and the upper portion ofwedge 36. More particularly, the outer diameter of gauge ring 38,relative to the inner walls of liner 10, may be such that it presents aleading edge sufficient to prevent plug 30 from being lowered intoconstrictions in liner 10 that are too narrow to allow passage of plug30. In some embodiments, the tolerances are such that it providessufficient clearance for plug 30 to be lowered past more typicallyencountered obstructions, protrusions, and bends in liner 10 withoutcatching or damage

In some embodiments, mandrel 39 of plug 30 may have an open cylindricalshape providing a central, axial mandrel bore 91. It is received anddisposed generally in bore 43 of wedge 34 and extends generally alongthe central axis of plug 30. When plug 30 is run into liner 10, as shownin FIG. 2A, mandrel 39 is releasably connected at its lower end to plug30. Mandrel 39 is releasably connected at its upper end to setting tool22 (not shown in FIG. 2A). As described further below, those releasableconnections allow plug 30 to be set and shut and allow setting tool 22to be released from plug 30.

More particularly, as shown in FIG. 2A, when plug 30 is run into a well,mandrel 39 is releasably connected to setting ring 37 of plug 30 by aplurality of frangible fasteners 73. Releases, such as frangible shearscrews 73 extend through threaded radial holes 74 (see FIGS. 5-6) inkeys 72 of setting ring 37 and into recesses such as grooves 92 (seeFIG. 9) at the lower end of mandrel 39. Shear screws 73 will be designedto break at a desired shear force and thereby release mandrel 39 fromplug 30 after plug 30 has been installed in liner 10. Other frangibleconnectors, such as pins, may be used for such purposes. Similarly,instead of grooves 92, mandrel 39 may be provided with a series ofdetents, spotfaces, or holes.

In some embodiments, mandrel 39 is releasably connected to setting tool22, either directly or indirectly through an associated adaptor (notshown in FIG. 2A), by a plurality of frangible fasteners 93. Frangibleshear screws 93 extend through radial holes in the setting tool 22 (oran associated adaptor) into threaded radial holes 94 in the upperportion of mandrel 39. Shear screws 93 will be designed to break at adesired shear force and thereby release setting tool 22 from mandrel 39after plug 30 has been set. Other frangible connectors, such as pins,may be used for such purposes. Similarly, instead of holes 94, mandrel39 may be provided with a series of grooves, detents, or spotfaces.

As best seen in FIG. 9 showing mandrel 39 in isolation, thoughsubstantially cylindrical, the outer circumference of mandrel 39 andmandrel bore 91 have various radial profiles along the length of mandrel39. In particular, the outer diameter of mandrel 39 tapers radiallyinward from an enlarged diameter mid-portion to provide a downwardfacing, external annular wedge seat 95. The enlarged diameter portionand taper is sized such that mandrel 39 can fit closely within wedge 34with wedge seat 95 seating on mandrel seat 44 in wedge bore 43.

It also will be noted that the upper portion of mandrel 39 has a reducedouter diameter relative to the mid-portion of mandrel 39. That reduceddiameter, upper portion provides annular clearance between mandrel 39and wedge 34. Mandrel bore 91 in the upper portion of mandrel 39 tapersinward to provide an upward facing, inner annular stopple seat 96. Ports97 extend through the upper portion of mandrel 39 allowing fluid to flowfrom the clearance between mandrel 39 and wedge 34 into bore 91 ofmandrel 39.

In some embodiments, stopple 31 may be barrel shaped, having annulartapers 32 at both ends. It is releasably fixed in mandrel bore 91 by aplurality of frangible fasteners 98 at a location that is spaced fromstopple seat 96 and above ports 97. Frangible shear screws 98 extendthrough threaded radial holes 99 (see FIG. 9) in mandrel 39 and intorecesses such as grooves 32 (see FIG. 9) in the mid-portion of stopple31. Shear screws 98 will be designed to break at a desired shear forceand thereby release stopple 31 from mandrel 39 after plug 30 has beeninstalled in liner 10. Other frangible connectors, such as pins, may beused for such purposes. Similarly, instead of grooves 33, stopple 31 maybe provided with a series of detents, spotfaces, or holes.

Once coupled to setting tool 22, either directly or through anassociated adaptor, frac plug 30 may be deployed and installed in awell. It may be deployed by pumping it along with tool string 20 intoliner 10 on wireline 23. Plug 30 will be installed by actuating settingtool 22 via wireline 23. Setting tool 22 may be any number ofconventional setting tools. Preferred setting tools and adaptors, andthe way they may be employed are disclosed in greater detail in Harris'003. In some embodiments, the setting tool and any associated adaptorcomprise an inner part and an outer part which move relative to eachother. When actuated, the outer part moves downward relative to theinner part and transmits force to wedge 34 of plug 30. Thus, whenactuated setting tool 22 will drive annular wedge 34 into sealing ring35 and annular slip 36 to force sealing ring 35 and slip 36 to expandand set and seal plug 30 in liner 10 as shown in FIG. 2B.

More particularly, once plug 30 is deployed to the desired location inliner 10, setting tool 22 may be actuated. Mandrel 39 is releasablyconnected to the inner part of setting tool 22 or an associated adaptor.The outer part of setting tool 22 will move downward relative to theinner part of setting tool 22. The outer part of setting tool 22 bearsdown on the upper end of wedge 34 which, as noted above, carries sealingring 35 and extends through slip 36 and setting ring 37. Sealing ring 35abuts the upper end of slip 36, and setting ring 37 abuts the lower endof slip 36. Setting ring 37 is held in position by mandrel 39, to whichit is connected by frangible fasteners 73. Collet fingers 41 of wedge34, however, are able to slide freely within the bore of setting ring37. That will allow plug 30 to be installed, in essence, by compressingwedge 34, sealing ring 35, and slip 36 together between the outer partof setting tool 22 and setting ring 37.

In some embodiments, as wedge 34 travels axially downward, thecomplementary conical surfaces on the upper portion of wedge 34 and inthe bore of sealing ring 35 and bore 61 of slip 36 allow wedge 34 toride under sealing ring 35 and slip 36. As wedge 34 rides under sealingring 35 and slip 36, it forces them to expand radially. As sealing ring35 expands radially, outer elastomeric seal 52 seals against liner 10and inner elastomeric seal 53 seals against the outer conical surface 45of wedge 34. Sealing ring 35 is thus able to provide a seal between plug30 and liner 10.

As slip 36 is expanded radially by wedge 34, slip segments 36 a-f willbe forced radially outward and eventually into contact with liner 10.Thus jammed between outer conical surface 45 of wedge 34 and liner 10,they are able to anchor plug 30 within liner 10. Upper end of slip 36abuts the lower end of sealing ring 35, thus also providing hard backupfor sealing ring 35 as it expands radially to seal against liner 10.

As noted above, mandrel 39 may be releasably connected at its upper endto the inner part of setting tool 22 by frangible fasteners 93. Whenwedge 34 has been fully driven into sealing ring 35 and slip 36, adownward facing, beveled shoulder at the lower end of upper portion ofwedge 34 will engage setting ring 37. Sealing ring 35 and slip 36 alsowill have been expanded into engagement with liner 10. At that point theshear forces across frangible fasteners 93 will increase rapidly. Whenthose forces exceed a predetermined limit, frangible fasteners 93 willshear, releasing setting tool 22 from mandrel 39 and relieving anyfurther compressive force on plug 30. Setting tool 22 then may be pulledfrom liner 10 via wireline 23.

FIG. 2B shows plug 30 after it has been set, but before stopple 31 hasbeen deployed. Fluid is still able to flow through plug 30. Fluid pumpeddown liner 10 at lower flow rates will flow into the clearance betweenthe upper portion of mandrel 39 and wedge 34, through ports 97 inmandrel 39, through mandrel bore 91, and out plug 30. If flow exceeds apredetermined rate, however, the resulting back pressure above stopple31 will cause shear screws 98 to shear, releasing stopple 31 andallowing it to flow downward through mandrel bore 91. The tapered end 32of stopple 31 provides a seating surface, and stopple 31 will seat onstopple seat 96 in mandrel 39 as shown in FIG. 2C. Once seated, stopple31 will be below ports 97 in mandrel 39 and will substantially restrictor in some embodiments shut off fluid flow through mandrel bore 91.

At that point hydraulic pressure on stopple 31 will increase rapidly,and shear screws 74 securing mandrel 39 to setting ring 37 will shear.Mandrel 39 will be released and will shift downward within wedge bore43. As shown in FIG. 2D, wedge seat 95 of mandrel 39 will seat onmandrel seat 44 of wedge 34 fully shutting plug 30. Fluid then may bediverted at high pressure and flow rates through perforations 24 intoformation 5. The setting ring 37 in some embodiments will maintain itsrelative position with respect to the mandrel 39 as shear screws (orretaining screws) 73 remain in place (this action is not shown in FIG.2D). In other embodiments as shown in FIG. 2D, the mandrel 39 willadvance relative to the setting ring 37 upon, among other things,release of shear screws/retaining screws 73. In certain embodiments, asflow or pressure increases, the order of movement of stopple and seatingof the mandrel within the inner wedge 45 can be altered, such that thestopple moves first and the seating occurs second, or vice versa.

It will be appreciated, therefore, that the plugs not only may beefficiently and effectively used to isolate portions of the liner, butthat they offer significant advantages to operators in situations wherefailure of perf guns is a particular concern. For example, plug 30 maybe installed in liner 10 as shown in FIG. 2B. Like conventionalball-on-seat plugs, plug 30 allows an operator to pressure test the plugbefore fracturing operations are commenced. After plug 30 is set, fluidmay be pumped into liner 10 at sufficiently high rates and pressures toshear screws 98 and release stopple 31. Plug 30 will be deployed at thispoint. If perf gun 21 fails to fire, stopple 31 remains in place and asecond perf gun 21 can be circulated into position. In certain otherembodiments, stopple 31 may be allowed to flow up and out of liner 10with production fluids. Another perf gun 21 then may be pumped intoliner 10.

Unlike conventional ball-on-seat plugs, however, if plug 30 is notpressure tested, plug 30 may allow a new perf gun 21 to be pumped intoliner 10 without having to flow stopple 31 out of the well. If the firstperf gun 21 fails to fire, stopple 31 is still held in mandrel 39 and aflow path through plug 30 is still available. Perf gun 21 and settingtool 22 may be pulled out of liner 10. Another perf gun 21 may be pumpedinto liner 10 so long as the threshold back pressure above stopple 31 isnot exceeded. Fluid essentially flows around stopple 31 via ports 97 inmandrel 39. Once the new perf gun 21 has been fired successfully, flowmay be increased to release stopple 31 from mandrel 39. Perforations 24have been provided in liner 10 and plug 30 has been shut—all withoutflowing stopple 31 back out of liner 10 with production fluids.

It will be appreciated that the plugs have been illustrated by referenceto barrel-shaped stopple 31. That configuration is preferred for variousreasons. Its cylindrical central portion allows stopple 31 to shifteasily and reliably within mandrel bore 91, yet it provides adequatesurface area to facilitate easy and reliable attachment to mandrel 39.By providing both ends with identical annular tapers 32, stopple 31 maybe installed with either end oriented toward stopple seat 96 in mandrelbore 91. Stopples, however, may have other geometries. Spherical ballsmay be used, for example, as they can be moved reliably though tubularsand provide effective seals. In general, any geometry allowing thestopple to shift and seat reliably may be used so long as theconfiguration of the seat is modified accordingly.

Similarly, ports 97 passing through mandrel 39 provide an effectivebypass allowing fluid to flow around stopple 31 until stopple 31 isreleased and plug 30 is shut. Ports 97 may be sized and numbered toprovide relative high flow rates through plug 34 without releasingstopple 31. Other bypass flow paths, however, may be provided. Forexample, stopple 31 fits relatively closely within mandrel bore 91, butit may instead have a reduced outer diameter relative to the diameter ofmandrel bore 91. Fluid would be allowed to flow around the periphery ofstopple 31. Alternately, grooves may be provided in the outer surface ofstopple 31, or passages provided near the its periphery to create otheraxial flow paths, while still providing a sufficiently large seatingsurface at the end of stopple 31. Similarly, while stopple 31 isillustrated as being releasably secured within mandrel bore 91, it maybe spaced away from stopple seat 96 and above ports 96 by collapsible orfrangible braces. Back pressure caused by fluid flowing through ports 96would collapse or break the brace when a threshold pressure is reached,allowing stopple 31 to seat on stopple seat 96.

Other modifications may be made to illustrative plug 30 in addition tothose mentioned above. For example, outer surface 45 of wedge 34, thebore of sealing ring 35, and bore 61 of slip 36 all have been describedas having an inverted truncated conical shape. The mating taperedsurfaces of wedge 34, sealing ring 35, and slip 36, however, may havedifferent geometries. Wedge 34, for example, may be provided with anumber of discrete, flat ramped surfaces arrayed circumferentially aboutits outer surface 45. Such ramps may be visualized as bevels or asgrooves on a conical surface or, as the sides of a tapered prism havinga polygonal cross-section. The bore of sealing ring 35 and bore 61 ofslip 36 would be modified so that they mate with and accommodate wedge34 as it is driven downward. For example, the plug may be provided withdiscrete slip segments which ride up flat grooves or tracks provided inthe wedge. A slip also may have a break-away configuration. Breakawayslips are designed to break apart into a number of segments as the slipis expanded radially during setting of the plug. Many otherconfigurations also may be used to connect the mandrel to the settingring or other plug components which allow the plug to be set. Multiplewedges, slips, and sealing elements also may be used. In general,mandrel 39 and stopple 31 and other embodiments thereof may be adaptedfor use in almost any conventional plug design.

FIGS. 11-21 show a frac plug 30, as a second exemplary frac plug, inaccordance with some of the embodiments.

As shown in FIG. 11, frac plug 30 may comprise an annular wedge 34, asealing ring 35, an annular slip 36, a setting ring 37, a gauge ring 38,a mandrel 39, and a stopple 31. Wedge 34, portions of sealing ring 35,and slip 36 may have truncated inverted conical or other taperedsurfaces. Those surfaces complement each other and allow wedge 34 to bedriven into and radially expand sealing ring 35 and slip 36 to seal andanchor plug 30 in liner 10.

FIG. 12-14 show an isomeric cross-sectional view, an isomeric wholeview, and a top exploded cross-sectional view of the frac plug 30 shownin FIG. 11.

FIG. 15 shows a set view of the frac plug 30 shown in FIG. 11 at momentwhen wireline setting tool is disengaged (elements and wireline shearscrews removed from image for clarity). In this drawing, tool is set incasing and no pressure retaining at this point.

FIG. 16 shows a set in view of the frac plug 30 shown in FIG. 11 duringflow and prior to “Conversion”. At this stage, flow is allowed to passthrough the ports up to a predetermined rate. Initial flow causes themandrel to shift back down to the cone. FIG. 17 is the same view as FIG.16 while showing the flow with dotted lines.

In some embodiments, ports 97 may extend through the upper portion ofmandrel 39 allowing fluid to flow from the clearance between mandrel 39and wedge 34 into bore 91 of mandrel 39. Fluid pumped down liner 10 atlower flow rates may flow into the clearance between the upper portionof mandrel 39 and wedge 34, through ports 97 in mandrel 39, throughmandrel bore 91, and out plug 30. If flow exceeds a predetermined rate,however, the resulting back pressure above stopple 31 will cause shearscrews 98 to shear (e.g. break), releasing stopple 31 and allowing it toflow downward through mandrel bore 91. In some embodiments, such ahydraulic back pressure is called hydraulic back pressure threshold,meaning by exceeding this hydraulic back pressure, the stopple will bereleased and will seal the plug. The tapered end 32 of stopple 31provides a seating surface, and stopple 31 will seat on stopple seat 96in mandrel 39. Once seated, stopple 31 will be below ports 97 in mandrel39 and will substantially restrict or in some embodiments shut off (e.gseal) fluid flow through mandrel bore 91.

In some embodiments, multiple ports are positioned circumferentiallyaround the mandrel. In some embodiments, the number of ports may be 4,5, 6, 7, 8, 10, or 12. In some embodiments, the ports may have the samedimension. In some embodiments, the ports may have different dimensions.In some embodiments, the ports may have a circle, oval, ellipse, square,triangle, rectangle, trapezoid, kite, pentagon, hexagon, octagon, orother complex cross sectional geometries.

In some embodiments, the ports may be protruded at 90 degrees angle ofoff the axial mandrel bore. In many embodiments, angled ports arepreferable, between 10 and 80 degrees off the axial direction of thetool. In some embodiments, the ports may be protruded at 30 degreesangle of off the axial mandrel bore. In some embodiments, the ports maybe protruded at 45 degrees angle of off the axial mandrel bore. In someembodiments, the ports may be protruded at 60 degrees angle of off theaxial mandrel bore. In some embodiments, the ports may be protruded atdifferent angles of off the axial mandrel bore. In some embodiments, amandrel may have four identical flow path ports spaced circumferentiallyat 90 degrees apart from each other and protruded with a 30 degreesangle of off the axial mandrel bore. In various embodiments, tests haveshown that angled ports within 5 degrees of 60 degrees off parallel withthe axis (i.e., 60°+/−10 degrees, or 20-40° off the axial direction) ofthe tool have shown superior flow-through capabilities. In theseembodiments, the back pressure can have sufficient separation from thelow flow pressure to allow release a release (e.g., the shear screws) atachievable pressures but distant enough from ordinary flow pressure tolimit accidental shear.

In some embodiments, ports may have groves or other features. Suchfeatures may be used to direct the flow to a specific direction or causea specific Reynolds numbers that would yield the hydraulic back pressurethreshold.

At that point hydraulic pressure on stopple 31 will increase rapidly,and shear screws 74 securing mandrel 39 to setting ring 37 will shear.Mandrel 39 will be released and will shift downward within wedge bore43. As shown in FIG. 2D, wedge seat 95 of mandrel 39 will seat onmandrel seat 44 of wedge 34 fully shutting plug 30. Fluid then may bediverted at high pressure and flow rates through perforations 24 intoformation 5.

It will be appreciated, therefore, that the plugs not only may beefficiently and effectively used to isolate portions of the liner, butthat they offer significant advantages to operators in situations wherefailure of perf guns is a particular concern. For example, plug 30 maybe installed in liner 10 as shown in FIG. 2B. Like conventionalball-on-seat plugs, plug 30 allows an operator to pressure test the plugbefore fracturing operations are commenced. After plug 30 is set, fluidmay be pumped into liner 10 at sufficiently high rates and pressures toshear screws 98 and release stopple 31. Plug 30 will be shut and may bepressure tested. If perf gun 21 fails to fire, like conventionalball-on-seat plugs, stopple 31 may be allowed to flow up and out ofliner 10 with production fluids. Another perf gun 21 then may be pumpedinto liner 10.

Unlike conventional ball-on-seat plugs, however, if plug 30 is notpressure tested, plug 30 may allow a new perf gun 21 to be pumped intoliner 10 without having to flow stopple 31 out of the well. If the firstperf gun 21 fails to fire, stopple 31 is still held in mandrel 39 and aflow path through plug 30 is still available. Perf gun 21 and settingtool 22 may be pulled out of liner 10. Another perf gun 21 may be pumpedinto liner 10 so long as the threshold back pressure above stopple 31 isnot exceeded. Fluid essentially flows around stopple 31 via ports 97 inmandrel 39. Once the new perf gun 21 has been fired successfully, flowmay be increased to release stopple 31 from mandrel 39, and to releasemandrel 39 from setting ring 37. Perforations 24 have been provided inliner 10 and plug 30 has been shut—all without flowing stopple 31 backout of liner 10 with production fluids.

It will be appreciated that the plugs have been illustrated by referenceto barrel-shaped stopple 31. That configuration is preferred for variousreasons. Its cylindrical central portion allows stopple 31 to shifteasily and reliably within mandrel bore 91, yet it provides adequatesurface area to facilitate easy and reliable attachment to mandrel 39.By providing both ends with identical annular tapers 32, stopple 31 maybe installed with either end oriented toward stopple seat 96 in mandrelbore 91. Stopples, however, may have other geometries. Spherical ballsmay be used, for example, as they can be moved reliably though tubularsand provide effective seals. In general, any geometry allowing thestopple to shift and seat reliably may be used so long as theconfiguration of the seat is modified accordingly.

Similarly, ports 97 passing through mandrel 39 provide an effectivebypass allowing fluid to flow around stopple 31 until stopple 31 isreleased and plug 30 is shut. Ports 97 may be sized and numbered toprovide relative high flow rates through plug 34 without releasingstopple 31. Other bypass flow paths, however, may be provided. Forexample, stopple 31 fits relatively closely within mandrel bore 91, butit may instead have a reduced outer diameter relative to the diameter ofmandrel bore 91. Fluid would be allowed to flow around the periphery ofstopple 31. Alternately, grooves may be provided in the outer surface ofstopple 31, or passages provided near the its periphery to create otheraxial flow paths, while still providing a sufficiently large seatingsurface at the end of stopple 31. Similarly, while stopple 31 isillustrated as being releasably secured within mandrel bore 91, it maybe spaced away from stopple seat 96 and above ports 96 by collapsible orfrangible braces. Back pressure caused by fluid flowing through ports 96would collapse or break the brace when a threshold pressure is reached,allowing stopple 31 to seat on stopple seat 96.

In some embodiments, plugs may be fabricated from materials and bymethods used in plugs of this type. Such materials may be relativelyhard metals, especially if removal of the plugs is not necessary, butthe materials may be relatively soft, more easily drilled materials. Forexample, wedge 34 and slip 36 may be fabricated from non-metallicmaterials commonly used in plugs, such as fiberglass and carbon fiberresinous materials. The components may be molded, or may be machinedfrom wound fiber resin blanks, such as a wound fiberglass cylinder.Alternately, suitable wedges and slips may be fabricated from softer ormore brittle metals that are easier to drill, such as surface hardenedcast iron, especially cast iron having a surface hardness in the rangeof 50-60 Rockwell C. Such materials and methods of fabricating wedge andslip components are well known in the art and may be obtainedcommercially from many sources. It also will be noted that, as usedherein, the term “bore” is only used to indicate that a passage existsand does not imply that the passage necessarily was formed by a boringprocess.

In some embodiments, the sealing ring in the plugs are fabricated from asufficiently ductile material which allows the ring to expand radiallyinto contact with a liner without breaking. For example, ring body 51may be fabricated from aluminum, bronze, brass, brass, copper, mildsteel, or magnesium and magnesium alloys. Alternately, the ring body maybe made of hard, elastomeric rubbers, such as butyl rubber.

In some embodiments, however, the sealing ring may be fabricated from aplastic material. Plastic components are more easily drilled, and theresulting debris more easily circulated out of a well. Engineeringplastics, that is, plastics having better thermal and mechanicalproperties than more commonly used plastics, are preferred. Variousmaterials that may be used are disclosed in Harris '003. As noted above,the sealing ring may be provided with elastomeric material around itsouter or inner surface. Such elastomeric materials include thosecommonly employed in downhole tools, such as butyl rubbers, hydrogenatednitrile butadiene rubber (HNBR) and other nitrile rubbers, andfluoropolymer elastomers such as Viton. Such elastomeric materials alsomay be used to fabricate other types of sealing elements as are commonlyused in frac plugs.

Though described to a certain extent, it will be appreciated that plug30 and other embodiments of the plugs may incorporate additional shearscrews and the like to immobilize components during assembly, shipping,or run-in of the plug. Additional set screws and the like may beprovided to prevent unintentional disassembly. Other sealing elementsmay be provided between components, and various ports accommodatingfluid flow around and through the assembly also may be provided. Suchfeatures are shown to a certain degree in the figures, but their designand use in tools such as the plugs is well known and well within theskill of workers in the art. In many respects, therefore, discussion ofsuch features is omitted from this description of preferred embodiments.

Plug 30 and other embodiments have been described as installed in aliner and, more specifically, a production liner used to fracture a wellin various zones along the wellbore. A “liner,” however, can have afairly specific meaning within the industry, as do “casing” and“tubing.” In its narrow sense, a “casing” is generally considered to bea relatively large tubular conduit, usually greater than 4.5″ indiameter that extends into a well from the surface. A “liner” isgenerally considered to be a relatively large tubular conduit that doesnot extend from the surface of the well, and instead is supported withinan existing casing or another liner. In essence, it is a “casing” thatdoes not extend from the surface. “Tubing” refers to a smaller tubularconduit, usually less than 4.5″ in diameter. The plugs, however, are notlimited in their application to liners as that term may be understood inits narrow sense. They may be used to advantage in liners, casings,tubing, and other tubular conduits or “tubulars” as are commonlyemployed in oil and gas wells. A reference to liners shall be understoodas a reference to all such tubulars.

Likewise, while the exemplified plugs are particularly useful infracturing a formation and have been exemplified in that context, theymay be used advantageously in other processes for stimulating productionfrom a well. For example, an aqueous acid such as hydrochloric acid maybe injected into a formation to clean up the formation and ultimatelyincrease the flow of hydrocarbons into a well. In other cases,“stimulation” wells may be drilled near a “production” well. Water orother fluids then would be injected into the formation through thestimulation wells to drive hydrocarbons toward the production well. Theplugs may be used in all such stimulation processes where it may bedesirable to create and control fluid flow in defined zones through awellbore. Though fracturing a wellbore is a common and importantstimulation process, the plugs are not limited thereto.

While this invention has been disclosed and discussed primarily in termsof specific embodiments thereof, it is not intended to be limitedthereto. Other modifications and embodiments will be apparent to theworker in the art.

Some of those embodiments are described is some detail herein. For thesake of conciseness, however, all features of an actual implementationmay not be described or illustrated. In developing any actualimplementation, as in any engineering or design project, numerousimplementation-specific decisions must be made to achieve a developers'specific goals. Decisions usually will be made consistent withinsystem-related and business-related constraints, and specific goals mayvary from one implementation to another. Development efforts might becomplex and time consuming and may involve many aspects of design,fabrication, and manufacture. Nevertheless, it should be appreciatedthat such development projects would be a routine effort for those ofordinary skill having the benefit of this disclosure.

The frac plugs may be used in fracturing operations. They also may beused in other stimulation operations. Broad embodiments of the fracplugs have a mandrel, a wedge, a slip, a sealing element, and a stopple.The mandrel has an axial mandrel bore, a stopple seat, and a portadapted to provide a flow path for fluid between the mandrel bore andthe exterior of the mandrel. The wedge, slip, and sealing element allare disposed radially beyond the mandrel. The stopple is releasablyspaced from the stopple seat and the port, and it is releasable to seaton the stopple seat by increasing hydraulic back pressure above theports.

The reader should appreciate that the present application describesseveral independently useful techniques. Rather than separating thosetechniques into multiple isolated patent applications, applicants havegrouped these techniques into a single document because their relatedsubject matter lends itself to economies in the application process. Butthe distinct advantages and aspects of such techniques should not beconflated. In some cases, embodiments address all of the deficienciesnoted herein, but it should be understood that the techniques areindependently useful, and some embodiments address only a subset of suchproblems or offer other, unmentioned benefits that will be apparent tothose of skill in the art reviewing the present disclosure. Due to costsconstraints, some techniques disclosed herein may not be presentlyclaimed and may be claimed in later filings, such as continuationapplications or by amending the present claims. Similarly, due to spaceconstraints, neither the Abstract nor the Summary of the Inventionsections of the present document should be taken as containing acomprehensive listing of all such techniques or all aspects of suchtechniques.

It should be understood that the description and the drawings are notintended to limit the present techniques to the particular formdisclosed, but to the contrary, the intention is to cover allmodifications, equivalents, and alternatives falling within the spiritand scope of the present techniques as defined by the appended claims.Further modifications and alternative embodiments of various aspects ofthe techniques will be apparent to those skilled in the art in view ofthis description. Accordingly, this description and the drawings are tobe construed as illustrative only and are for the purpose of teachingthose skilled in the art the general manner of carrying out the presenttechniques. It is to be understood that the forms of the presenttechniques shown and described herein are to be taken as examples ofembodiments. Elements and materials may be substituted for thoseillustrated and described herein, parts and processes may be reversed oromitted, and certain features of the present techniques may be utilizedindependently, all as would be apparent to one skilled in the art afterhaving the benefit of this description of the present techniques.Changes may be made in the elements described herein without departingfrom the spirit and scope of the present techniques as described in thefollowing claims. Headings used herein are for organizational purposesonly and are not meant to be used to limit the scope of the description.

As used throughout this application, the word “may” is used in apermissive sense (i.e., meaning having the potential to), rather thanthe mandatory sense (i.e., meaning must). The words “include”,“including”, and “includes” and the like mean including, but not limitedto. As used throughout this application, the singular forms “a,” “an,”and “the” include plural referents unless the content explicitlyindicates otherwise. Thus, for example, reference to “an element” or “aelement” includes a combination of two or more elements, notwithstandinguse of other terms and phrases for one or more elements, such as “one ormore.” The term “or” is, unless indicated otherwise, non-exclusive,i.e., encompassing both “and” and “or.” Terms describing conditionalrelationships, e.g., “in response to X, Y,” “upon X, Y,”, “if X, Y,”“when X, Y,” and the like, encompass causal relationships in which theantecedent is a necessary causal condition, the antecedent is asufficient causal condition, or the antecedent is a contributory causalcondition of the consequent, e.g., “state X occurs upon condition Yobtaining” is generic to “X occurs solely upon Y” and “X occurs upon Yand Z.” Such conditional relationships are not limited to consequencesthat instantly follow the antecedent obtaining, as some consequences maybe delayed, and in conditional statements, antecedents are connected totheir consequents, e.g., the antecedent is relevant to the likelihood ofthe consequent occurring. Statements in which a plurality of attributesor functions are mapped to a plurality of objects (e.g., one or moreprocessors performing steps A, B, C, and D) encompasses both all suchattributes or functions being mapped to all such objects and subsets ofthe attributes or functions being mapped to subsets of the attributes orfunctions (e.g., both all processors each performing steps A-D, and acase in which processor 1 performs step A, processor 2 performs step Band part of step C, and processor 3 performs part of step C and step D),unless otherwise indicated. Further, unless otherwise indicated,statements that one value or action is “based on” another condition orvalue encompass both instances in which the condition or value is thesole factor and instances in which the condition or value is one factoramong a plurality of factors. Unless otherwise indicated, statementsthat “each” instance of some collection have some property should not beread to exclude cases where some otherwise identical or similar membersof a larger collection do not have the property, i.e., each does notnecessarily mean each and every. Limitations as to sequence of recitedsteps should not be read into the claims unless explicitly specified,e.g., with explicit language like “after performing X, performing Y,” incontrast to statements that might be improperly argued to imply sequencelimitations, like “performing X on items, performing Y on the X'editems,” used for purposes of making claims more readable rather thanspecifying sequence. Statements referring to “at least Z of A, B, andC,” and the like (e.g., “at least Z of A, B, or C”), refer to at least Zof the listed categories (A, B, and C) and do not require at least Zunits in each category. Unless specifically stated otherwise, asapparent from the discussion, it is appreciated that throughout thisspecification discussions utilizing terms such as “processing,”“computing,” “calculating,” “determining” or the like refer to actionsor processes of a specific apparatus, such as a special purpose computeror a similar special purpose electronic processing/computing device.Features described with reference to geometric constructs, like“parallel,” “perpendicular/orthogonal,” “square”, “cylindrical,” and thelike, should be construed as encompassing items that substantiallyembody the properties of the geometric construct, e.g., reference to“parallel” surfaces encompasses substantially parallel surfaces. Thepermitted range of deviation from Platonic ideals of these geometricconstructs is to be determined with reference to ranges in thespecification, and where such ranges are not stated, with reference toindustry norms in the field of use, and where such ranges are notdefined, with reference to industry norms in the field of manufacturingof the designated feature, and where such ranges are not defined,features substantially embodying a geometric construct should beconstrued to include those features within 15% of the definingattributes of that geometric construct. The terms “first”, “second”,“third,” “given” and so on, if used in the claims, are used todistinguish or otherwise identify, and not to show a sequential ornumerical limitation. As is the case in ordinary usage in the field,data structures and formats described with reference to uses salient toa human need not be presented in a human-intelligible format toconstitute the described data structure or format, e.g., text need notbe rendered or even encoded in Unicode or ASCII to constitute text;images, maps, and data-visualizations need not be displayed or decodedto constitute images, maps, and data-visualizations, respectively;speech, music, and other audio need not be emitted through a speaker ordecoded to constitute speech, music, or other audio, respectively.

The present techniques will be better understood with reference to thefollowing enumerated embodiments:

A plug apparatus, the apparatus comprising: a cone shaped wedge having afirst end and a second end and having an inside surface and an outsidesurface, the cone shaped wedge having, at least in some part, adecreasing diameter on the outside surface from the first end to thesecond end; a slip, comprising a tapered inner surface, configured toencircle the second end of the cone shaped wedge; a sealing ring, havingan annular body, encircled around the cone shaped wedge and near thefirst end of the cone shaped wedge; and a mandrel positioned inside thecone shaped wedge, the mandrel having an open cylindrical shape andhaving a first end and a second end, the mandrel comprising: an axialmandrel bore; a stopple seat in the axial mandrel bore; a plurality offlow path ports adapted to allow fluid to enter the axial mandrel bore,wherein: the plurality of flow path ports are positioned between thefirst end of the mandrel and the stopple seat; and the plurality of flowpath ports are protruded with a 60 degrees angle+/−10 degrees of off theaxial mandrel bore; and a stopple positioned between the plurality offlow path ports and the first end of the mandrel; and one or morereleases configured to releasably fixing the position of the stopple inthe axial mandrel bore.

The plug apparatus of claim 1, wherein: the mandrel having an insidesurface and an outside surface; and the plurality of flow path ports arepositioned circumferentially around the mandrel, wherein the pluralityof flow path ports are configured to direct the fluid from the outsidesurface of the mandrel to the inside surface of the mandrel and towardsthe second end of the mandrel.

The plug apparatus of claim 2, wherein: the releases comprise frangibleor shearable parts adapted to fail at an identified pressure; and thestopple is releasable to seat on the stopple seat by reaching ahydraulic back pressure threshold above the plurality of flow path portsupon failing of the plurality of frangible or shearable parts.

The plug apparatus of claim 2, wherein: the plurality of flow path portscomprises four identical flow path ports spaced circumferentially at 90degrees apart from each other.

The plug apparatus of claim 1, the cone shaped wedge further comprising:a plurality of collet fingers or rods extended axially and spacedcircumferentially on the second end of the cone shaped wedge.

The plug apparatus of claim 5, the plug further comprising: a settingring having an annular body, the setting ring comprising: a plurality ofkeys arranged circumferentially and protruded radially inward on thesetting ring; and wherein the setting ring is positioned slidably aroundthe plurality of collet fingers.

The plug apparatus of claim 6, the plug further comprising: a gauge ringattached to the plurality of collet fingers or rods and extended aroundthe setting ring.

The plug apparatus of claim 1, the slip comprising: a plurality ofindividual slip segments positioned closely adjacent and angularlyaround the cone shaped wedge.

The plug apparatus of claim 8, wherein: the individual slip segments areequally spaced.

The plug apparatus of claim 8, wherein: each of the individual slipsegments comprises a plurality of buttons made of a ceramic materialcontaining aluminum.

The plug apparatus of claim 1, wherein: the stopple comprises atruncated cone portion.

The plug apparatus of claim 11, wherein: the stopple comprises a solidcylindrical portion.

The plug apparatus of claim 1, wherein: the stopple has dimensionssuitable for being received in the stopple seat, as a means to restrictlongitudinal flow passage through the plug apparatus.

The plug apparatus of claim 1, wherein: the stopple seat comprises atapered shape facing the first end of the mandrel.

The plug apparatus of claim 1, wherein: the mandrel comprises an outerwedge seat configured to seat on a mandrel seat.

The plug apparatus of claim 1, wherein: the diameter of the cone shapedwedge decreases at a constant linear rate, at least in some part, on theoutside surface.

The plug apparatus of claim 1, the sealing ring comprising: a grooveconfigured to receive a plurality of elasticity rings to hydraulicallyseal a liner.

The plug apparatus of claim 1, wherein the slip further comprises: aplurality of gripping serrations as a means of locking mechanism toprevent any dismantlement.

A method of plugging a liner bore; the method comprising: running a pluginto a liner to a location to be plugged, the plug comprising: a coneshaped wedge having a first end and a second end and having an insidesurface and an outside surface, the cone shaped wedge having, at leastin some part, a decreasing diameter on the outside surface from thefirst end to the second end; a slip, comprising a tapered inner surface,configured to encircle the second end of the cone shaped wedge; asealing ring, having an annular body, encircled around the cone shapedwedge and near the first end of the cone shaped wedge; and a mandrelpositioned inside the cone shaped wedge, the mandrel having an opencylindrical shape and having a first end and a second end, the mandrelcomprising: an axial mandrel bore; a stopple seat in the axial mandrelbore; a stopple; a plurality of frangible shear screws positioned nearthe first end of the mandrel; and a plurality of flow path ports adaptedto allow fluid to enter the axial mandrel bore, wherein: the pluralityof flow path ports are positioned between the first end of the mandreland the stopple seat; and the plurality of flow path ports are protrudedwith a 60 degrees+/−10 degrees angle of off the axial mandrel bore; andsetting the plug in the liner; and dropping the stopple into the stoppleseat by reaching a hydraulic back pressure threshold in the liner.

What is claimed is:
 1. A plug apparatus, the apparatus comprising: acone shaped wedge having a first end and a second end and having aninside surface and an outside surface, the cone shaped wedge having, atleast in some part, a decreasing diameter on the outside surface fromthe first end to the second end; a slip, comprising a tapered innersurface, configured to encircle the second end of the cone shaped wedge;a sealing ring, having an annular body, encircled around the cone shapedwedge and near the first end of the cone shaped wedge; and a mandrelpositioned inside the cone shaped wedge, the mandrel having an opencylindrical shape and having a first end and a second end, the mandrelcomprising: an axial mandrel bore; a stopple seat in the axial mandrelbore; a plurality of flow path ports adapted to allow fluid to enter theaxial mandrel bore, wherein: the plurality of flow path ports arepositioned between the first end of the mandrel and the stopple seat;and the plurality of flow path ports are protruded with a 60 degreesangle+/−10 degrees of off the axial mandrel bore; and a stopplepositioned between the plurality of flow path ports and the first end ofthe mandrel; and one or more releases configured to releasably fixingthe position of the stopple in the axial mandrel bore.
 2. The plugapparatus of claim 1, wherein: the mandrel having an inside surface andan outside surface; and the plurality of flow path ports are positionedcircumferentially around the mandrel, wherein the plurality of flow pathports are configured to direct the fluid from the outside surface of themandrel to the inside surface of the mandrel and towards the second endof the mandrel.
 3. The plug apparatus of claim 2, wherein: the releasescomprise frangible or shearable parts adapted to fail at an identifiedpressure; and the stopple is releasable to seat on the stopple seat byreaching a hydraulic back pressure threshold above the plurality of flowpath ports upon failing of the plurality of frangible or shearableparts.
 4. The plug apparatus of claim 2, wherein: the plurality of flowpath ports comprises four identical flow path ports spacedcircumferentially at 90 degrees apart from each other.
 5. The plugapparatus of claim 1, the cone shaped wedge further comprising: aplurality of collet fingers or rods extended axially and spacedcircumferentially on the second end of the cone shaped wedge.
 6. Theplug apparatus of claim 5, the plug further comprising: a setting ringhaving an annular body, the setting ring comprising: a plurality of keysarranged circumferentially and protruded radially inward on the settingring; and wherein the setting ring is positioned slidably around theplurality of collet fingers.
 7. The plug apparatus of claim 6, the plugfurther comprising: a gauge ring attached to the plurality of colletfingers or rods and extended around the setting ring.
 8. The plugapparatus of claim 1, the slip comprising: a plurality of individualslip segments positioned closely adjacent and angularly around the coneshaped wedge.
 9. The plug apparatus of claim 8, wherein: the individualslip segments are equally spaced.
 10. The plug apparatus of claim 1,wherein: the stopple comprises a truncated cone portion.
 11. The plugapparatus of claim 10, wherein: the stopple comprises a solidcylindrical portion.
 12. The plug apparatus of claim 1, wherein: thestopple has dimensions suitable for being received in the stopple seat,as a means to restrict longitudinal flow passage through the plugapparatus.
 13. The plug apparatus of claim 1, wherein: the stopple seatcomprises a tapered shape facing the first end of the mandrel.
 14. Theplug apparatus of claim 1, wherein: the mandrel comprises an outer wedgeseat configured to seat on a mandrel seat.
 15. The plug apparatus ofclaim 1, wherein: the diameter of the cone shaped wedge decreases at aconstant linear rate, at least in some part, on the outside surface. 16.The plug apparatus of claim 1, the sealing ring comprising: a grooveconfigured to receive a plurality of elasticity rings to hydraulicallyseal a liner.
 17. The plug apparatus of claim 1, wherein the slipfurther comprises: a plurality of gripping serrations as a means oflocking mechanism to prevent any dismantlement.
 18. A method of plugginga liner bore, the method comprising: running a plug into a liner to alocation to be plugged, the plug comprising: a cone shaped wedge havinga first end and a second end and having an inside surface and an outsidesurface, the cone shaped wedge having, at least in some part, adecreasing diameter on the outside surface from the first end to thesecond end; a slip, comprising a tapered inner surface, configured toencircle the second end of the cone shaped wedge; a sealing ring, havingan annular body, encircled around the cone shaped wedge and near thefirst end of the cone shaped wedge; and a mandrel positioned inside thecone shaped wedge, the mandrel having an open cylindrical shape andhaving a first end and a second end, the mandrel comprising: an axialmandrel bore; a stopple seat in the axial mandrel bore; a stopple; aplurality of frangible shear screws positioned near the first end of themandrel; and a plurality of flow path ports adapted to allow fluid toenter the axial mandrel bore, wherein: the plurality of flow path portsare positioned between the first end of the mandrel and the stoppleseat; and the plurality of flow path ports are protruded with a 60degrees+/−10 degrees angle of off the axial mandrel bore; and settingthe plug in the liner; and dropping the stopple into the stopple seat byreaching a hydraulic back pressure threshold in the liner.